Methods of creating high porosity propped fractures

ABSTRACT

Methods of forming a high porosity propped fracture comprising: providing a slurry comprising a fracturing fluid, proppant particulates, and a weighting agent; introducing the slurry into a portion of a fracture within the subterranean formation; and, depositing the proppant particulates into the portion of the fracture within the subterranean formation so as to form a high porosity propped fracture. Methods of fracturing a subterranean formation to form a high porosity propped fracture comprising: creating at least one fracture within a portion of a subterranean formation; placing a slurry comprising a fracturing fluid, high density plastic particulates, and a weighting agent into at least a portion of the created fracture; and, depositing the high density plastic proppant particulates into a portion of the fracture so as to form a high porosity propped fracture. Slurries suitable for use in subterranean fracturing operations comprising: a fracturing fluid, proppant particulates, and a weighting agent.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a continuation in part of U.S. application Ser. No.10/937,076, filed on Sep. 9, 2004.

BACKGROUND

The present invention relates to high porosity propped fractures andmethods of creating high porosity propped fractures in portions ofsubterranean formations. More particularly, the present inventionrelates method of using weighting agents in fracturing fluids used tocreate high porosity propped fractures.

Subterranean wells (such as hydrocarbon producing wells, water producingwells, and injection wells) are often stimulated by hydraulic fracturingtreatments. In hydraulic fracturing treatments, a viscous fracturingfluid, which also functions as a carrier fluid, is pumped into a portionof a subterranean formation at a rate and pressure such that thesubterranean formation breaks down and one or more fractures are formed.Typically, particulate solids, such as graded sand, are suspended in aportion of the fracturing fluid are then deposited in the fractures.These particulate solids, or “proppant particulates,” serve to preventthe fractures from fully closing once the hydraulic pressure. By keepingthe fracture from fully closing, the proppant particulates aid informing conductive paths through which fluids may flow.

Commonly used proppant particulates generally comprise substantiallyspherical particles, such as graded sand, bauxite, ceramics, or even nuthulls. Generally, the proppant particulates are placed in the fracturein a concentration such that they formed a tight pack of particulates.Unfortunately, in such traditional operations, when fractures close uponthe proppant particulates they can crush or become compacted,potentially forming non-permeable or low permeability masses within thefracture rather than desirable high permeability masses; such lowpermeability masses may choke the flow path of the fluids within theformation. Furthermore, the proppant particulates may become embedded inparticularly soft formations, negatively impacting production.

The degree of success of a fracturing operation depends, at least inpart, upon fracture porosity and conductivity once the fracturingoperation is stopped and production is begun. Traditional fracturingoperations place a large volume of proppant particulates into a fractureand the porosity of the resultant packed propped fracture is thenrelated to the interconnected interstitial spaces between the abuttingproppant particulates. Thus, the resultant fracture porosity from atraditional fracturing operation is closely related to the strength ofthe placed proppant particulates (if the placed particulates crush thenthe pieces of broken proppant may plug the interstitial spaces) and thesize and shape of the placed particulate (larger, more sphericalproppant particulates generally yield increased interstitial spacesbetween the particulates). Such traditional fracturing operations tendto result in packed fractures that have porosities ranging from about26% to about 46%.

One way proposed to combat problems inherent in tight proppantparticulate packs involves placing a much reduced volume of proppantparticulates in a fracture to create what is referred to herein as apartial monolayer or “high porosity” fracture. In such operations theproppant particulates within the fracture may be widely spaced but theyare still sufficient to hold the fracture open and allow for production.Such operations allow for increased fracture conductivity due, at leastin part, to the fact the produced fluids may flow around widely spacedproppant particulates rather than just through the relatively smallinterstitial spaces in a packed proppant bed.

While this concept of partial monolayer fracturing was investigated inthe 1960's, the concept has not been successfully applied for a numberof reasons. One problem is that successful placement of a partialmonolayer of proppant particulates presents unique challenges in therelative densities of the particulates versus the carrier fluid. Anotherproblem lies in the fact that placing a proppant that tends to crush orembed under pressure may allow the fracture to pinch or close in placesonce the fracturing pressure is released. Still another problem is thatparticulates that could be carried in a fluid to potentially produce ahigh porosity fracture were then unable to support the load from theformation once the fracturing pressure was released. Attempts to solvethese problems have heretofore been unsuccessful.

SUMMARY

The present invention relates to high porosity propped fractures andmethods of creating high porosity propped fractures in portions ofsubterranean formations. More particularly, the present inventionrelates method of using weighting agents in fracturing fluids used tocreate high porosity propped fractures.

One embodiment of the present invention provides a method of forming ahigh porosity propped fracture in a subterranean formation, comprising:providing a slurry comprising a fracturing fluid, proppant particulates,and a weighting agent; introducing the slurry into a portion of afracture within the subterranean formation; and, depositing the proppantparticulates into the portion of the fracture within the subterraneanformation so as to form a high porosity propped fracture.

Another embodiment of the present invention provides a method offracturing a portion of a subterranean formation so as to form a highporosity propped fracture comprising: creating at least one fracturewithin a portion of a subterranean formation using hydraulic pressure;placing a slurry comprising a fracturing fluid, high density plasticparticulates, and a weighting agent into at least a portion of thecreated fracture; and, depositing the high density plastic proppantparticulates into a portion of the fracture so as to form a highporosity propped fracture.

Another embodiment of the present invention provides a slurry suitablefor use in subterranean fracturing operations comprising: a fracturingfluid, proppant particulates, and a weighting agent.

The features and advantages of the present invention will be readilyapparent to those skilled in the art upon a reading of the descriptionof the preferred embodiments that follows.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows the results of computer modeling simulating one embodimentof a high porosity propped fracture made using an adhesive substance.

FIG. 2 shows the results of a lab test simulating one embodiment of ahigh porosity propped fracture made using an adhesive substance.

FIG. 3 shows the results of computer modeling simulating one embodimentof a high porosity propped fracture made without an adhesive substance.

FIG. 4 shows the results of a lab test simulating one embodiment of ahigh porosity propped fracture made without an adhesive substance

FIG. 5 shows packed 16/30 sand proppant particles forming a pack havingabout 40% porosity.

FIG. 6 shows packed 16/20 ceramic proppant particles forming a packhaving about 40% porosity.

FIG. 7 shows a graph of fracture width versus conductivity with respectto fractures having various levels of porosity.

DETAILED DESCRIPTION

The present invention relates to high porosity propped fractures andmethods of creating high porosity propped fractures in portions ofsubterranean formations. More particularly, the present inventionrelates method of using weighting agents in fracturing fluids used tocreate high porosity propped fractures.

In certain methods of the present invention, proppant particulates aresuspended in a fracturing fluid that comprises a weighting agent andthen the suspended proppant particulates are sent down hole and placedinto a subterranean fracture so as to create a high porosity proppedfracture. The weighting agent in the fracturing fluid may be capable ofacting both to increase the fluid's density (and thus the ability of thefluid to suspend particulates) and also to act as a fluid loss controlmaterial. As used herein, the term “high porosity fracture” refers to aproppant fracture having a porosity greater than about 40%.

I. High-Porosity Propped Fractures

Porosity values expressed herein are unstressed porosities, that is, theporosity before the fracture has closed or applied any substantialmechanical stress. By way of example, to find porosity in one embodimentof the present invention a 70% porosity fracture was propped using Nylon6 proppant and, once 4,000 psi of stress was applied and the system wasallowed to come to rest, the resultant porosity was 58%. In that casethe unstressed porosity was 70% and the stressed porosity was 58%.

The methods of the present invention may be used, inter alia, to createhigh porosity fractures having increased conductivity as compared totraditional packed propped fractures. The greater conductivity isbelieved to be due, at least in part, to a high porosity fracture thatmay be formed using a lower than traditional proppant loading.

The ability to place lower than traditional proppant loading mayfacilitate the formation of a conductive fracture with porosity greaterthan about 40% while still maintaining enough conductive channels forproduction. Some embodiments of the present invention may be used toform a fracture exhibiting a porosity of at least about 50%. Otherembodiments of the present invention may be used to form a fractureexhibiting a porosity of at least about 60%. Other embodiments of thepresent invention may be used to form a fracture exhibiting a porosityof at least about 70%. Other embodiments of the present invention may beused to form a fracture exhibiting a porosity of at least about 80%.Other embodiments of the present invention may be used to form afracture exhibiting a porosity of at least about 90%. FIGS. 3 and 4illustrate some embodiments of arrangements of particles in a fracturehaving a 80% porosity.

The lower than traditional proppant loading as used in the presentinvention may allow for increased conductivity and increased proppantparticulate performance, at least in part, because the high porosityfractures they form allow for increased levels of open channels. With ahigh porosity fracture there may be more open spaces in the proppedfracture that may remain open, even under severe closure stresses thanfound in traditional, high proppant loading applications.

By increasing the percentage of open spaces within a propped fracture,the methods of the present invention may act not only to increase theavailable space for production but also to eliminate non-darcy effectsduring production. Generally, non-Darcy effects are caused by inertialforces due to expansion and contraction of the local flow inside flowchannels found in typical proppant packs. The high porosity proppedfractures, decrease or eliminate the cycles of expansion and contractionbecause the interstitial spaces found in traditional propped fracturesare not present. The article, Recent Advances in Hydraulic Fracturing,Gidley, J. L., et al. (ed.), Society of Petroleum Engineers, Richardson,Tex. (1989) discusses non-Darcy flow and its effects on conductivity ofproppant beds and fractures, its relevant teachings are herebyincorporated by reference.

FIG. 3 shows the results of computer modeling simulating one embodimentof a high porosity propped fracture having about 80% porosity formedusing cylindrical nylon 6 proppant particulates. FIG. 4 shows theresults of a lab test substantially similar to the operation modeled inFIG. 3, forming one embodiment of a high porosity propped fracturehaving about 80% porosity formed using cylindrical nylon 6 proppantparticulates. By contrast, FIGS. 5 and 6 each show proppant particulatesforming a traditional, dense pack having about 40% porosity (includingboth the porosity of the internal pack and that along the wall of thejar), wherein FIG. 5 is formed of 16/30 sand and FIG. 6 is formed of16/20 ceramic proppant. Fractures held open by proppant packs of sand orceramic proppants have an average porosity of about 40%. Notably,proppant size has little or no effect on the porosity of a packedfracture; rather, proppant size effects the permeability (and thereforethe conductivity) of a propped fracture.

FIG. 7 shows a graph of fracture width versus conductivity with respectto fractures having various levels of porosity. As shown in FIG. 7, aporosity (phi) of 100% would correspond to a 0% proppant loading. Asnoted above, the practical lower limit of porosity is about 40%. Aporosity value of 40% is considered reasonable for packed proppant bedsand although the porosity can vary, it generally varies only within asmall range (38 to 40%). Higher porosities leave more amounts of openspace through which produced fluids may flow, and are therefore,desirable.

The present invention describes reduced particulate loadings to create ahigh porosity fracture compared to traditional fracturing applicationsthat create packed fractures. Tables 1 and 2 provide example proppantloading schedules for a fracturing treatment. As will be understood byone skilled in the art, each operation is unique, and thus, may requireits own unique proppant addition schedule. However, the example in Table1 shows one possible addition schedule for achieving a high porosityfracture having a porosity in excess of about 90% for most of thepropped fracture area. By contrast, Table 2 shows the proppant additionschedule for an operation placing a traditional packed proppant bedwithin a fracture that results in a packed fracture with porosity around40% for most of the propped fracture area.

TABLE 1 High Porosity Fracture Treatment Proppant Addition ScheduleStage Volume Proppant Treatment Fluid name (gal) Concentration (lb/gal)Rate (BPM) Pad 7,500 0.0 25 Slurry 4,000 0.05 25 Slurry 4,000 0.1 25Slurry 4,000 0.2 25 Slurry 4,000 0.3 25 Slurry 3,000 0.4 25 Slurry 3,0000.5 25 Slurry 3,000 0.6 25 Flush 3,200 0.0 25 Totals 35,700 gal 7,100lbs

TABLE 2 Conventional Treatment Proppant Addition Schedule Stage VolumeProppant Treatment Fluid name (gal) Concentration (lb/gal) Rate (BPM)Pad 7,500 0 25 Slurry 4,000 0.5 25 Slurry 4,000 1 25 Slurry 4,000 2 25Slurry 4,000 3 25 Slurry 3,000 4 25 Slurry 3,000 5 25 Slurry 3,000 6 25Flush 3,200 0 25 Totals 35,700 gal 71,000 lbsII. Fracturing Fluids

Any fracturing fluid suitable for a fracturing or frac-packingapplication may be used in accordance with the teachings of the presentinvention, including aqueous gels, viscoelastic surfactant gels, oilgels, heavy brines, and emulsions. Suitable aqueous gels are generallycomprised of water and one or more gelling agents. Suitable emulsionscan be comprised of two immiscible liquids such as an aqueous liquid orgelled liquid and a hydrocarbon. Generally, suitable fracturing fluidsare relatively viscous, as will be understood by one skilled in the art,increasing the viscosity of a fracturing fluid may be accomplished bymany means, including, but not limited to, adding a heavy brine to thefluid, adding a polymer to the fluid, crosslinking a polymer in thefluid, or some combination thereof. In exemplary embodiments of thepresent invention, the fracturing fluids are aqueous gels comprised ofwater, a gelling agent for gelling the water and increasing itsviscosity, and, optionally, a crosslinking agent for crosslinking thegel and further increasing the viscosity of the fluid. The increasedviscosity of the gelled, or gelled and cross-linked, fracturing fluid,inter alia, reduces fluid loss and allows the fracturing fluid totransport significant quantities of suspended proppant particles. Thewater used to form the fracturing fluid may be salt water, brine, or anyother aqueous liquid that does not adversely react with the othercomponents. The density of the water can be increased to provideadditional particle transport and suspension in the present invention.

A variety of gelling agents may be used, including hydratable polymersthat contain one or more functional groups such as hydroxyl, carboxyl,sulfate, sulfonate, amino, or amide groups. Suitable gelling typicallycomprise polymers, synthetic polymers, or a combination thereof. Avariety of gelling agents can be used in conjunction with the methodsand compositions of the present invention, including, but not limitedto, hydratable polymers that contain one or more functional groups suchas hydroxyl, cis-hydroxyl, carboxylic acids, derivatives of carboxylicacids, sulfate, sulfonate, phosphate, phosphonate, amino, or amide. Incertain exemplary embodiments, the gelling agents may be polymerscomprising polysaccharides, and derivatives thereof that contain one ormore of these monosaccharide units: galactose, mannose, glucoside,glucose, xylose, arabinose, fructose, glucuronic acid, or pyranosylsulfate. Examples of suitable polymers include, but are not limited to,guar gum and derivatives thereof, such as hydroxypropyl guar andcarboxymethylhydroxypropyl guar, and cellulose derivatives, such ashydroxyethyl cellulose. Additionally, synthetic polymers and copolymersthat contain the above-mentioned functional groups may be used. Examplesof such synthetic polymers include, but are not limited to,polyacrylate, polymethacrylate, polyacrylamide, polyvinyl alcohol, andpolyvinylpyrrolidone. In other exemplary embodiments, the gelling agentmolecule may be depolymerized. The term “depolymerized,” as used herein,generally refers to a decrease in the molecular weight of the gellingagent molecule. Depolymerized gelling agent molecules are described inU.S. Pat. No. 6,488,091 issued Dec. 3, 2002 to Weaver, et al., therelevant disclosure of which is incorporated herein by reference.Suitable gelling agents generally are present in the viscosifiedtreatment fluids of the present invention in an amount in the range offrom about 0.1% to about 5% by weight of the water therein. In certainexemplary embodiments, the gelling agents are present in the viscosifiedtreatment fluids of the present invention in an amount in the range offrom about 0.01% to about 2% by weight of the water therein

Crosslinking agents may be used to crosslink gelling agent molecules toform crosslinked gelling agents. Crosslinkers typically comprise atleast one ion that is capable of crosslinking at least two gelling agentmolecules. Examples of suitable crosslinkers include, but are notlimited to, boric acid, disodium octaborate tetrahydrate, sodiumdiborate, pentaborates, ulexite and colemanite, compounds that cansupply zirconium IV ions (such as, for example, zirconium lactate,zirconium lactate triethanolamine, zirconium carbonate, zirconiumacetylacetonate, zirconium malate, zirconium citrate, and zirconiumdiisopropylamine lactate); compounds that can supply titanium IV ions(such as, for example, titanium lactate, titanium malate, titaniumcitrate, titanium ammonium lactate, titanium triethanolamine, andtitanium acetylacetonate); aluminum compounds (such as, for example,aluminum lactate or aluminum citrate); antimony compounds; chromiumcompounds; iron compounds; copper compounds; zinc compounds; or acombination thereof. An example of a suitable commercially availablezirconium-based crosslinker is “CL-24” available from Halliburton EnergyServices, Inc., Duncan, Okla. An example of a suitable commerciallyavailable titanium-based crosslinker is “CL-39” available fromHalliburton Energy Services, Inc., Duncan Okla. Suitable crosslinkersgenerally are present in the viscosified treatment fluids of the presentinvention in an amount sufficient to provide, inter alia, the desireddegree of crosslinking between gelling agent molecules. In certainexemplary embodiments of the present invention, the crosslinkers may bepresent in an amount in the range from about 0.001% to about 10% byweight of the water in the fracturing fluid. In certain exemplaryembodiments of the present invention, the crosslinkers may be present inthe viscosified treatment fluids of the present invention in an amountin the range from about 0.01% to about 1% by weight of the watertherein. Individuals skilled in the art, with the benefit of thisdisclosure, will recognize the exact type and amount of crosslinker touse depending on factors such as the specific gelling agent, desiredviscosity, and formation conditions.

The gelled or gelled and cross-linked fracturing fluids may also includeinternal delayed gel breakers such as enzyme, oxidizing, acid buffer, ortemperature-activated gel breakers. The gel breakers cause the viscouscarrier fluids to revert to thin fluids that can be produced back to thesurface after they have been used to place proppant particles insubterranean fractures. The gel breaker used is typically present in thefracturing fluid in an amount in the range of from about 0.5% to about10% by weight of the gelling agent. The fracturing fluids may alsoinclude one or more of a variety of well-known additives, such as gelstabilizers, fluid loss control additives, clay stabilizers,bactericides, and the like.

III. Weighting Agents

Weighting agents suitable for use in the present invention are particlescapable of acting to increase the density of the fracturing fluid.Moreover, weighting agents suitable for use in the present invention areparticles capable of acting as fluid loss control materials. Suitableweighting agents generally comprise small sized particulates such assilica flour. Generally, the size distribution of the weighting agentshould be selected such that it is capable of acting as a fluid losscontrol material for the formation being fractured; that is, the size ofthe weighting agent should be chosen to based, at least in part, on thepore size distribution of the formation being fractured. The commonwisdom has long held that the presence of particles small enough to actas fluid loss control materials should be avoided in fracturing fluids.This notion is primarily related to the fact that such materials weknown to clog the pore throats between the packed particles in theresultant packed proppant bed and thus to increase the resistance toflow of produced fluids through the bed. However, in the partialmonolayer high porosity propped fracture created in the presentinvention pore throats are only formed in those instances whereinmultiple proppant particulates group together, the expanse of thefracture is open space. Thus, there is little or no concern of cloggingpore throats in a high porosity propped fracture of the presentinvention.

By increasing the density of a fracturing fluid, suitable weightingagents may also act to increase the proppant suspending capacity of afracturing fluid comprising the weighting agent. In some embodiments ofthe present invention, the weighting agent may be used only incombination with a suitable viscosifier to increase the fracturingfluid's density and proppant suspending capacity. In fact, in someembodiments wherein it may be possible to use a drilling mud to fracturea formation and to place a high porosity proppant pack in the formation.In some embodiments of the present invention, the chosen weightingagent(s) may be added to the fracturing fluid in an amount sufficient tomake the fracturing fluid density substantially similar to the densityof the chosen proppant particulates.

Weighting agents suitable for use in the present invention include, butare not limited to, silica flour, particulate stone (such as ground andsized limestone or marble), graphitic carbon, ground battery casings,ground tires, calcium carbonate, barite, glass, mica, ceramics, grounddrill cuttings, combinations thereof, and the like.

IV. Suitable Proppant Particulates

A. Proppant Particulates—Size and Shape

Proppant particulates suitable for use in the methods of the presentinvention may be of any size and shape combination known in the art assuitable for use in a fracturing operation. Generally, where the chosenproppant is substantially spherical, suitable proppant particulates havea size in the range of from about 2 to about 400 mesh, U.S. SieveSeries. In some embodiments of the present invention, the proppantparticulates have a size in the range of from about 8 to about 120 mesh,U.S. Sieve Series.

In some embodiments of the present invention it may be desirable to usesubstantially non-spherical proppant particulates. Suitablesubstantially non-spherical proppant particulates may be cubic,polygonal, fibrous, or any other non-spherical shape. Such substantiallynon-spherical proppant particulates may be, for example, cubic-shaped,rectangular shaped, rod shaped, ellipse shaped, cone shaped, pyramidshaped, or cylinder shaped. That is, in embodiments wherein the proppantparticulates are substantially non-spherical, the aspect ratio of thematerial may range such that the material is fibrous to such that it iscubic, octagonal, or any other configuration. Substantiallynon-spherical proppant particulates are generally sized such that thelongest axis is from about 0.02 inches to about 0.3 inches in length. Inother embodiments, the longest axis is from about 0.05 inches to about0.2 inches in length. In one embodiment, the substantially non-sphericalproppant particulates are cylindrical having an aspect ratio of about1.5 to 1 and about 0.08 inches in diameter and about 0.12 inches inlength. In another embodiment, the substantially non-spherical proppantparticulates are cubic having sides about 0.08 inches in length. The useof substantially non-spherical proppant particulates may be desirable insome embodiments of the present invention because, among other things,they may provide a lower rate of settling when slurried into a fluid asis often done to transport proppant particulates to desired locationswithin subterranean formations. By so resisting settling, substantiallynon-spherical proppant particulates may provide improved proppantparticulate distribution as compared to more spherical proppantparticulates.

In poorly consolidated formations (that is, formations that, whenassessed, fail to produce a core sample that can be satisfactorilydrilled, cut, etc.) the use of substantially non-spherical proppantparticulates may also help to alleviate the embedment of proppantparticulates into the formation surfaces (such as a fracture face). Asis known by one skilled in the art, when substantially sphericalproppant particulates are placed against a formation surface understress, such as when they are used to prop a fracture, they are subjectto point loading. By contrast, substantially non-spherical proppantparticulates may be able to provide a greater surface area against theformation surface and thus may be better able to distribute the load ofthe closing fracture.

B. Proppant Particulates—Materials of Manufacture

Proppant particulates suitable for use in the present invention includegraded sand, resin coated sand, bauxite, ceramic materials, glassmaterials, walnut hulls, polymeric materials, resinous materials, rubbermaterials, and the like. In some embodiments of the present invention,the proppant particulates suitable for use in the present invention arecomposed of at least one high density plastic. As used herein, the term“high density plastic” refers to a plastic having a specific gravity ofgreater than about 1. The preferable density range is from about 1 toabout 2. More preferably the range is from about 1 to about 1.3. Themost preferable is from about 1.1 to 1.2. In addition to being a highdensity plastic, plastics suitable for use in the present inventiongenerally exhibit a crystallinity of greater than about 10%. In someembodiments, the high density plastic used to form the proppantparticulates of the present invention exhibits a crystallinity ofgreater than about 20%. While the material is referred to as “highdensity,” it will be readily understood by one skilled in the art thatthe density is “high” relative to other plastics, but may be low ascompared to traditional proppant particulate densities. For example,Ottawa sand may exhibit a specific gravity of about 2.65 whereasman-made ceramic proppants generally have specific gravities rangingfrom about 2.7 to about 3.6. The relatively low density of the highdensity plastics used to create the proppant particulates of the presentinvention may be beneficial to an even distribution when the proppantparticulates are slurried into a fluid such as a fracturing fluid. Sucheven distribution may be particularly helpful in forming a high porosityproppant pack that is capable of holding open the majority of afracture. Uneven distribution could result in a situation wherein aportion of a fracture is propped while another portion is substantiallyvoid of proppant particulates and thus, does not remain open once thehydraulic pressure is released.

Some well-suited high density plastic materials include polyamide 6(Nylon 6), polyamide 66 (Nylon 6/6), acrylic, acrylonitrile butadienestyrene (ABS), ethylene vinyl alcohol, polycarbonate/PET polyesterblend, polyethylene terephthalate (PET), unreinforcedpolycarbonate/polybutylene terephthalate (PC/PBT) blend, PETGcopolyester, polyetherimide, polyphenylene ether, molded polyphenylenesulfide (PPS), heat resistant grade polystyrene, polyvinylbenzene,polyphenylene oxide, a blend of polyphenylene oxide and nylon 6/6,acrylonitrile-butadiene-styrene, polyvinylchloride, fluoroplastics,polysulfide, polypropylene, styrene acrylonitrile, polystyrene,phenylene oxide, polyolefins, polystyrene divinylbenzene,polyfluorocarbons, polyethers etherketones, polyamide imides, andcombinations thereof. Some other well-suited high density plasticmaterials include oil-resistant thermoset resins such as acrylic-basedresins, epoxy-based resins, furan-based resins, phenolic-based resins,phenol/phenol formaldehyde/furfuryl alcohol resins, polyester resins,and combinations thereof.

In some embodiments of the present invention it may be desirable toreinforce the proppant particulates made of high density plastic toincrease their resistance to a crushing or deforming force. Suitablereinforcing materials include high strength particles such as bauxite,nut hulls, ceramic, metal, glass, sand, asbestos, mica, silica, alumina,and any other available material that is smaller in size than thedesired, final high density plastic proppant particulate and that iscapable of adding structural strength to the desired, final high densityplastic proppant particulate. In some embodiments of the presentinvention the reinforcing material may be a fibrous material such asglass fibers or cotton fibers. Preferably, the reinforcing material ischosen so as to not unduly increase the specific gravity of the finalproppant particulate.

One benefit of using proppant particulates formed from high densityplastic is that they may be created on-the-fly during a fracturing orfrac-packing operation. U.S. patent application Ser. No. 10/853,879filed May 26, 2004 and titled “On-The-Fly Preparation of Proppant andits Use in Subterranean Operations,” the relevant disclosure of which ishereby incorporated by reference, describes methods of creating proppantparticulates from thermoplastic materials on-the-fly. As described inthat application, one example of a method for preparing proppanton-the-fly generally comprises providing a mixture comprising athermoplastic/thermosetting polymer, and a filler, heating the resinmixture, extruding, atomizing, or spraying the mixture to particulateform into a well bore containing a treatment fluid; and allowing theextruded particulate to substantially cure and form proppant particles.This method relies, at least in part, on the ability ofthermoplastic/thermosetting materials to be extruded from a liquid format an elevated temperature, and then as the material cools, to thenharden and form into a solid material. The thermoplastic orthermosetting proppant particulates can be prepared on-the-fly,according to the present invention, to a suitable size and shape.

Density and strength of proppant particulates formed fromthermoplastic/thermosetting materials may be customized to meet thefracturing designs and well conditions. To help eliminate the problemsthat may be caused by large particle size, in one embodiment theon-the-fly thermoplastic proppant particulates may be introduced intothe fracturing fluid at the discharge side of the pump. As will berecognized by one skilled in the art, during pumping of such on-the-flyproppant particulates (particularly where the flow passes through one ormore perforations), the proppant particulates may break into smallersizes as a result of high shear as they are being placed inside aportion of a subterranean formation.

V. Adhesive Substances Suitable for Use in the Present Invention

In some embodiments, the proppant particulates are coated with anadhesive substance, so that they will have the tendency to adhere to oneanother when they come into contact. The adhesive should be strongenough that the proppant particulates remain clustered together whileunder static condition or under low shear rates. As the shear rateincreases, the proppant clusters or aggregates may become dispersed intosmaller clusters or even individual proppant particulates. Thisphenomenon may repeat again and again from the time the coated proppantis introduced into the fracturing fluid, pumped into the well bore andfracture, and even after being placed inside the fracture. In someembodiments, coating the proppant particulates with an adhesivesubstance may (via the tacky nature of the adhesive substance) encouragethe formation of aggregates of proppant particulates that may then formpillars within the fracture. As used herein, the term “adhesivesubstance” refers to a material that is capable of being coated onto aparticulate and that exhibits a sticky or tacky character such that theproppant particulates that have adhesive thereon have a tendency tocreate clusters or aggregates. As used herein, the term “tacky,” in allof its forms, generally refers to a substance having a nature such thatit is (or may be activated to become) somewhat sticky to the touch.

FIGS. 1 and 2 illustrate the formation of aggregates of proppantparticulates coated with an adhesive substance. FIGS. 1 and 2 illustrateexperiments designed just as FIGS. 3 and 4 (discussed above) with theone exception that the embodiments show in FIGS. 1 and 2 use proppantparticulates coated with an adhesive substance. FIG. 1 shows the resultsof computer modeling simulating one embodiment of a high porositypropped fracture having about 80% porosity formed using cylindricalnylon 6 proppant particulates coated with 2% by weight of the proppantparticulates an adhesive substance (Sandwedge®, commercially availablefrom Halliburton Energy Services, Duncan Okla.). FIG. 2 shows theresults of a lab test substantially similar to the operation modeled inFIG. 1, forming one embodiment of a high porosity propped fracturehaving about 80% porosity formed using cylindrical nylon 6 proppantparticulates coated with 2% by weight of the proppant particulates anadhesive substance (Sandwedge®, commercially available from HalliburtonEnergy Services, Duncan Okla.).

Adhesive substances suitable for use in the present invention includenon-aqueous tackifying agents; aqueous tackifying agents; silyl-modifiedpolyamides; and curable resin compositions that are capable of curing toform hardened substances. In addition to encouraging the proppantparticulates to form aggregates, the use of an adhesive substance mayyield a propped fracture that experiences very little or no undesirableproppant flow back. As described in more detail above, the applicationof an adhesive substance to the proppant particulates used to create ahigh porosity fracture may aid in the formation of aggregates thatincrease the ability of a small amount of proppant particulates toeffectively hold open a fracture for production. Adhesive substances maybe applied on-the-fly, applying the adhesive substance to the proppantparticulate at the well site, directly prior to pumping thefluid-proppant mixture into the well bore.

A. Adhesive Substances—Non-Aqueous Tackifying Agents

Tackifying agents suitable for use in the consolidation fluids of thepresent invention comprise any compound that, when in liquid form or ina solvent solution, will form a non-hardening coating upon aparticulate. A particularly preferred group of non-aqueous tackifyingagents comprise polyamides that are liquids or in solution at thetemperature of the subterranean formation such that they are, bythemselves, non-hardening when introduced into the subterraneanformation. A particularly preferred product is a condensation reactionproduct comprised of commercially available polyacids and a polyamine.Such commercial products include compounds such as mixtures of C₃₆dibasic acids containing some trimer and higher oligomers and also smallamounts of monomer acids that are reacted with polyamines. Otherpolyacids include trimer acids, synthetic acids produced from fattyacids, maleic anhydride, acrylic acid, and the like. Such acid compoundsare commercially available from companies such as Witco Corporation,Union Camp, Chemtall, and Emery Industries. The reaction products areavailable from, for example, Champion Technologies, Inc. and WitcoCorporation. Additional compounds which may be used as tackifyingcompounds include liquids and solutions of, for example, polyesters,polycarbonates and polycarbamates, natural resins such as shellac andthe like. Other suitable tackifying agents are described in U.S. Pat.No. 5,853,048 issued to Weaver, et al. and U.S. Pat. No. 5,833,000issued to Weaver, et al., the relevant disclosures of which are hereinincorporated by reference.

Non-aqueous tackifying agents suitable for use in the present inventionmay be either used such that they form non-hardening coating or they maybe combined with a multifunctional material capable of reacting with thenon-aqueous tackifying compound to form a hardened coating. A “hardenedcoating” as used herein means that the reaction of the tackifyingcompound with the multifunctional material will result in asubstantially non-flowable reaction product that exhibits a highercompressive strength in a consolidated agglomerate than the tackifyingcompound alone with the particulates. In this instance, the tackifyingagent may function similarly to a hardenable resin. Multifunctionalmaterials suitable for use in the present invention include, but are notlimited to, aldehydes such as formaldehyde, dialdehydes such asglutaraldehyde, hemiacetals or aldehyde releasing compounds, diacidhalides, dihalides such as dichlorides and dibromides, polyacidanhydrides such as citric acid, epoxides, furfuraldehyde, glutaraldehydeor aldehyde condensates and the like, and combinations thereof. In someembodiments of the present invention, the multifunctional material maybe mixed with the tackifying compound in an amount of from about 0.01 toabout 50 percent by weight of the tackifying compound to effectformation of the reaction product. In some preferable embodiments, thecompound is present in an amount of from about 0.5 to about 1 percent byweight of the tackifying compound. Suitable multifunctional materialsare described in U.S. Pat. No. 5,839,510 issued to Weaver, et al., therelevant disclosure of which is herein incorporated by reference. Othersuitable tackifying agents are described in U.S. Pat. No. 5,853,048issued to Weaver, et al.

Solvents suitable for use with the non-aqueous tackifying agents of thepresent invention include any solvent that is compatible with thetackifying agent and achieves the desired viscosity effect. The solventsthat can be used in the present invention preferably include thosehaving high flash points (most preferably above about 125° F.). Examplesof solvents suitable for use in the present invention include, but arenot limited to, butylglycidyl ether, dipropylene glycol methyl ether,butyl bottom alcohol, dipropylene glycol dimethyl ether,diethyleneglycol methyl ether, ethyleneglycol butyl ether, methanol,butyl alcohol, isopropyl alcohol, diethyleneglycol butyl ether,propylene carbonate, d'limonene, 2-butoxy ethanol, butyl acetate,furfuryl acetate, butyl lactate, dimethyl sulfoxide, dimethyl formamide,fatty acid methyl esters, and combinations thereof. It is within theability of one skilled in the art, with the benefit of this disclosure,to determine whether a solvent is needed to achieve a viscosity suitableto the subterranean conditions and, if so, how much.

B. Adhesive Substances—Aqueous Tackifying Agents

Suitable aqueous tackifying agents are capable of forming at least apartial coating upon the surface of a particulate (such as a proppantparticulate). Generally, suitable aqueous tackifying agents are notsignificantly tacky when placed onto a particulate, but are capable ofbeing “activated” (that is destabilized, coalesced and/or reacted) totransform the compound into a sticky, tackifying compound at a desirabletime. Such activation may occur before, during, or after the aqueoustackifying agent is placed in the subterranean formation. In someembodiments, a pretreatment may be first contacted with the surface of aparticulate to prepare it to be coated with an aqueous tackifying agent.Suitable aqueous tackifying agents are generally charged polymers thatcomprise compounds that, when in an aqueous solvent or solution, willform a non-hardening coating (by itself or with an activator) and, whenplaced on a particulate, will increase the continuous criticalresuspension velocity of the particulate when contacted by a stream ofwater (further described in Example 7). The aqueous tackifying agent mayenhance the grain-to-grain contact between the individual particulateswithin the formation (be they proppant particulates, formation fines, orother particulates), helping bring about the consolidation of theparticulates into a cohesive, flexible, and permeable mass.

Examples of aqueous tackifying agents suitable for use in the presentinvention include, but are not limited to, acrylic acid polymers,acrylic acid ester polymers, acrylic acid derivative polymers, acrylicacid homopolymers, acrylic acid ester homopolymers (such as poly(methylacrylate), poly (butyl acrylate), and poly(2-ethylhexyl acrylate)),acrylic acid ester co-polymers, methacrylic acid derivative polymers,methacrylic acid homopolymers, methacrylic acid ester homopolymers (suchas poly(methyl methacrylate), poly(butyl methacrylate), andpoly(2-ethylhexyl methacryate)), acrylamido-methyl-propane sulfonatepolymers, acrylamido-methyl-propane sulfonate derivative polymers,acrylamido-methyl-propane sulfonate co-polymers, and acrylicacid/acrylamido-methyl-propane sulfonate co-polymers and combinationsthereof. Methods of determining suitable aqueous tackifying agents andadditional disclosure on aqueous tackifying agents can be found in U.S.patent application Ser. No. 10/864,061 and filed Jun. 9, 2004 and U.S.patent application Ser. No. 10/864,618 and filed Jun. 9, 2004 therelevant disclosures of which are hereby incorporated by reference.

C. Adhesive Substances—Silyl-Modified Polyamides

Silyl-modified polyamide compounds suitable for use as an adhesivesubstance in the methods of the present invention may be described assubstantially self-hardening compositions that are capable of at leastpartially adhering to particulates in the unhardened state, and that arefurther capable of self-hardening themselves to a substantiallynon-tacky state to which individual particulates such as formation fineswill not adhere to, for example, in formation or proppant pack porethroats. Such silyl-modified polyamides may be based, for example, onthe reaction product of a silating compound with a polyamide or amixture of polyamides. The polyamide or mixture of polyamides may be oneor more polyamide intermediate compounds obtained, for example, from thereaction of a polyacid (e.g., diacid or higher) with a polyamine (e.g.,diamine or higher) to form a polyamide polymer with the elimination ofwater. Other suitable silyl-modified polyamides and methods of makingsuch compounds are described in U.S. Pat. No. 6,439,309 issued toMatherly, et al., the relevant disclosure of which is hereinincorporated by reference.

D. Adhesive Substances—Curable Resins

Resins suitable for use in the consolidation fluids of the presentinvention include all resins known in the art that are capable offorming a hardened, consolidated mass. Many such resins are commonlyused in subterranean consolidation operations, and some suitable resinsinclude two component epoxy based resins, novolak resins, polyepoxideresins, phenol-aldehyde resins, urea-aldehyde resins, urethane resins,phenolic resins, furan resins, furan/furfuryl alcohol resins,phenolic/latex resins, phenol formaldehyde resins, polyester resins andhybrids and copolymers thereof, polyurethane resins and hybrids andcopolymers thereof, acrylate resins, and mixtures thereof. Some suitableresins, such as epoxy resins, may be cured with an internal catalyst oractivator so that when pumped down hole, they may be cured using onlytime and temperature. Other suitable resins, such as furan resinsgenerally require a time-delayed catalyst or an external catalyst tohelp activate the polymerization of the resins if the cure temperatureis low (i.e., less than 250° F.), but will cure under the effect of timeand temperature if the formation temperature is above about 250° F.,preferably above about 300° F. It is within the ability of one skilledin the art, with the benefit of this disclosure, to select a suitableresin for use in embodiments of the present invention and to determinewhether a catalyst is required to trigger curing.

Any solvent that is compatible with the resin and achieves the desiredviscosity effect is suitable for use in the present invention. Preferredsolvents include those listed above in connection with tackifyingcompounds. It is within the ability of one skilled in the art, with thebenefit of this disclosure, to determine whether and how much solvent isneeded to achieve a suitable viscosity.

To facilitate a better understanding of the present invention, thefollowing examples of preferred embodiments are given. In no way shouldthe following examples be read to limit or define the scope of theinvention.

EXAMPLES

Table 3 illustrates the conductivity that may be achieved when forminghigh porosity propped fractures of the present invention. The data shownin Table 3 represents a high porosity propped fracture comprisingproppant particulates having a flattened pillow shape (substantiallynon-spherical) at a surface area concentration of about 0.09 pounds persquare foot versus substantially spherical 20/40 mesh Ottawa sand atabout two pounds per square foot and not having an adhesive coating. Ata closure stress of about 2000 psi and at 105° F., a high porosityfracture formed using proppant particulates of the present invention hasabout ten times the conductivity of a pack formed from 20/40 mesh Ottawasand at about two pounds per square foot. At a closure stress of about3000 psi and at 150° F., a high porosity fracture formed using proppantparticulates of the present invention was over two and a half times asconductive as the pack formed from 20/40 mesh Ottawa sand at about twopounds per square foot. At a closure stress of about 4000 psi and at150° F., a high porosity fracture formed using proppant particulates ofthe present invention was over two and a quarter times as conductive asthe pack formed from 20/40 mesh Ottawa sand at about two pounds persquare foot. The high porosity fracture formed using proppantparticulates of the present invention shows a porosity of about 70% atthe start and reduced to about 58% at a closure stress of about 4000 psiand at 150° F.

TABLE 3 Fracture conductivity data for flattened pillow shaped particlesand conventional 20/40 mesh sand. Conductivity (md-ft) Closure stress2.78 gm Nylon 6X 20/40 Sand (psi) and (70% porosity Packed FractureTemperature (° F.) fracture) (40% porosity fracture) 2000 and 105° 389653981 2500 and 105° 27722 — 3000 and 105° 20798 — 3000 and 150° 9194 35314000 and 150° 6695 2939

Table 4 shows data for another material that can be used (cylindricalparticles) for the present invention. Here the created fracture porosityranges from 80% to 88%. The higher porosity fracture provides thegreatest conductivity values. The addition of an adhesive agent(Sandwedge®, commercially available from Halliburton Energy Services,Duncan Okla.) to create clusters shows there is additional increasedconductivity due to larger channels being created. The porosity remainsat 80% but the conductivity is increased due to the large channels.

TABLE 4 Fracture conductivity data for cylindrical particles in twoconcentrations and conventional 20/40 mesh sand Conductivity (md-ft)2.78 gm Nylon 6 20/40 Sand Closure stress 2.78 gm Nylon 6 w/2% adhesive1.85 gm Nylon 6 Packed Fracture (psi) and (80% porosity agent (80% (88%porosity (40% porosity Temperature (° F.) fracture) porosity fracture)fracture) fracture) 2000 and 105° 12863 44719 19950 3981 2500 and 105°11207 35579 15603 — 3000 and 105°  8789 29808 11975 — 3000 and 150° —18375 5574 3531 4000 and 150° — 15072 3277 2939

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Whilenumerous changes may be made by those skilled in the art, such changesare encompassed within the spirit of this invention as defined by theappended claims.

1. A method of forming a high porosity propped fracture in asubterranean formation, comprising: providing a slurry comprising afracturing fluid, proppant particulates, and a weighting agent;introducing the slurry into a portion of a fracture within thesubterranean formation; and, depositing the proppant particulates intothe portion of the fracture within the subterranean formation so as toform a high porosity propped fracture without the addition of an acidicafterflush.
 2. The method of claim 1 wherein the weighting agent isselected from the group consisting of: silica flour, particulate stone,graphitic carbon, ground battery casings, ground tires, calciumcarbonate, barite, glass, mica, ceramics, ground drill cuttings, andcombinations thereof.
 3. The method of claim 1 wherein the weightingagent is a fluid loss control agent or a density increasing agent. 4.The method of claim 1 wherein the high porosity propped fracture has aporosity of at least about 50%.
 5. The method of claim 1 wherein atleast a portion of the proppant particulates are selected from the groupconsisting of: high density plastic, graded sand, resin coated sand,bauxite, a ceramic material, a glass material, nut hulls, a polymericmaterial, a resinous material, a rubber material, and a combinationthereof.
 6. The method of claim 1 wherein at least a portion of theproppant particulates are substantially coated with an adhesivesubstance selected from the group consisting of: a non-aqueoustackifying agent; an aqueous tackifying agent; a silyl-modifiedpolyamide; a curable resin composition; and a combination thereof. 7.The method of claim 1 wherein the fracturing fluid is selected from thegroup consisting of: a drilling fluid, water, an aqueous gel, aviscoelastic surfactant gel, an oil gel, a heavy brine, an emulsion, anda combination thereof.
 8. A method of fracturing a portion of asubterranean formation so as to form a high porosity propped fracturecomprising: creating at least one fracture within a portion of asubterranean formation using hydraulic pressure; placing a slurrycomprising a fracturing fluid, high density plastic proppantparticulates, and a weighting agent into at least a portion of thefracture; and, depositing the high density plastic proppant particulatesinto a portion of the fracture so as to form a high porosity proppedfracture.
 9. The method of claim 8 wherein the weighting agent isselected from the group consisting of: silica flour, particulate stone,graphitic carbon, ground battery casings, ground tires, calciumcarbonate, barite, glass, mica, ceramics, ground drill cuttings, andcombinations thereof.
 10. The method of claim 8 wherein the weightingagent is a fluid loss control agent or a density increasing agent. 11.The method of claim 8 wherein the high porosity propped fracture has aporosity of at least about 50%.
 12. The method of claim 8 wherein theslurry further comprises proppant particulates selected from the groupconsisting of: graded sand, resin coated sand, bauxite, a ceramicmaterial, a glass material, nut hulls, a polymeric material, a resinousmaterial, a rubber material, and a combination thereof.
 13. The methodof claim 8 wherein at least a portion of the high density plasticproppant particulates are substantially coated with an adhesivesubstance selected from the group consisting of: a non-aqueoustackifying agent; an aqueous tackifying agent; a silyl-modifiedpolyamide; a curable resin composition; and a combination thereof. 14.The method of claim 8 wherein the fracturing fluid is selected from thegroup consisting of: a drilling fluid, water, an aqueous gel, aviscoelastic surfactant gel, an oil gel, a heavy brine, an emulsion, anda combination thereof.
 15. A method of treating at least a portion of asubterranean formation, comprising: providing a slurry comprising afracturing fluid and proppant particulates; introducing the slurry intoa portion of a fracture within the subterranean formation; and,depositing the proppant particulates into the portion of the fracturewithin the subterranean formation so as to form a high porosity proppedfracture without the addition of an acidic afterflush.
 16. The method ofclaim 15 wherein the proppant particulates comprise a high densityplastic.
 17. The method of claim 16 wherein the high density plastic isselected from the group consisting of: polyamide 6 (Nylon 6), polyamide66 (Nylon 6/6), acrylic, acrylonitrile butadiene styrene (ABS), ethylenevinyl alcohol, polycarbonate/PET polyester blend, polyethyleneterephthalate (PET), unreinforced polycarbonate/polybutyleneterephthalate (PC/PBT) blend, PETG copolyester, polyetherimide,polyphenylene ether, molded polyphenylene sulfide (PPS), heat resistantgrade polystyrene, polyvinylbenzene, polyphenylene oxide, a blend ofpolyphenylene oxide and nylon 6/6, acrylonitrile-butadiene-styrene,polyvinylchloride, fluoroplastics, polysulfide, polypropylene, styreneacrylonitrile, polystyrene, phenylene oxide, polyolefins, polystyrenedivinylbenzene, polyfluorocarbons, polyethers etherketones, polyamideimides, and combinations thereof.
 18. The method of claim 16 wherein thehigh density plastic is selected from the group consisting of:acrylic-based resins, epoxy-based resins, furan-based resins,phenolic-based resins, phenol/phenol formaldehyde/furfuryl alcoholresins, polyester resins, and combinations thereof.
 19. The method ofclaim 15 wherein the proppant particulates further comprise areinforcing material.
 20. The method of 18 wherein the reinforcingmaterial is selected from the group consisting of: bauxite, nut hulls,ceramic, metal, glass, sand, asbestos, mica, silica, alumina, glassfibers, cotton fibers, and combinations thereof.